Methods and systems for natural gas purification integrated with gas compression

ABSTRACT

Methods and systems are disclosed to compress raw, liquids-rich natural gas to high pressures while removing heavier hydrocarbons and water through inter-stage gas processing. Some variations provide a method for purifying and compressing natural gas, comprising: conveying a methane-containing input stream to first-compression stages; generating an initial compressed gas stream at a first pressure; conveying the initial compressed gas stream to a low-temperature separation sub-system configured to remove liquid contaminants, thereby generating an intermediate compressed gas stream at a second pressure; conveying the intermediate compressed gas stream to second-compression stages, to generate a compressed gas product stream at a third pressure; recovering purified and compressed natural gas; and feeding the compressed gas product stream into a mobile container. The sub-systems are preferably integrated into a single unit. The invention solves several problems associated with processing and transporting raw natural gas from initial production locations to end markets for final use.

PRIORITY DATA

This non-provisional patent application claims priority to U.S. Provisional Patent App. No. 63/226,235, filed on Jul. 28, 2021, which is hereby incorporated by reference herein.

FIELD OF THE INVENTION

The present invention generally relates systems and methods for producing purified and compressed natural gas for a variety of uses.

BACKGROUND OF THE INVENTION

Traditional natural gas midstream systems consists of a complex network of pipelines, compressors, fixed gas processing plants, high-pressure sales pipes, and interstate pipelines to effectively transport the natural gas from the wellhead at which it is produced, to end markets in acceptable quality for final consumption. Natural gas is aggregated from wellheads in raw form, into a volume for processing whereby water, natural gas liquid (“NGL”) components, and any additional contaminants (e.g., hydrogen sulfide) are removed prior to compression and transportation via pipeline to end markets for consumption.

In shale-oil basins, associated gas is produced in tandem with the oil from an oil well. Associated gas is typically rich in natural gas liquids including ethane, propane, butanes, and pentanes. This associated gas typically only represents 20-40% of the total “barrels of energy equivalent” from an oil well's production stream. With methane having such a consistently low market price, the associated natural gas stream may only represent <10% of the total revenue stream of the oil well. Associated gas volumes in oil plays have a high decline rate, in that their production rate falls dramatically after the first 3 to 6 months, with production rates typically only 20-50% of the initial production rates of the well after 12 months. In addition, the gas/oil ratio (“GOR”) in each well can change over time, with trends showing increased GOR as an oil basin matures. Associated gas is conventionally regarded as a factor to be minimized, in favor of oil production, operationally and economically. Gas infrastructure is planned and built to minimize expense/cost, rather than to maximize volume.

The above realities make it very difficult for midstream companies to plan infrastructure capacities to accommodate a dynamic supply picture. Additionally, the investment in gas transportation infrastructure requires a great deal of extra capacity (capital) for the early stages of the well's life, for a very short period (6 to 12 months) compared to the total life of a well (20+years). It typically takes up to 18 months or more for midstream companies to invest, construct, and commission new gas processing or pipeline facilities. Meanwhile, with drilling and completion technologies and techniques always being optimized to produce shorter and shorter cycle times, multi-well pads in major shale oil basins (Bakken, Permian, etc.) can typically be drilled and completed in as little as 3-4 months.

Additionally, natural gas gathering pipelines face issues related to regulatory, geography, permitting, landowner, and social concerns, which can slow the construction timelines. The delays, in turn, cause mismatch issues with gas production and traditional midstream transportation and processing capacity.

Typically, natural gas is processed through a refrigeration plant, which lowers the temperature of the gas at specific pressures, to allow the different NGL components to drop out of the gas and be stored separately. Natural gas processing through refrigeration is the industry-standard technology and has been around for 100+years. Gas processing plants are most efficient at large scale; gas plants typically range in size from 10 MMCFD to 500+MMCFD. These plants require high capital cost, significant time to build, and a high degree of throughput to maintain good economics.

For these reasons, particularly in oil-shale plays, natural gas gathering infrastructure is consistently built to be under-sized for the initial production rates or for any future growth or changes to the existing producer activities. Excess gas that cannot be transported by the gas gathering and processing infrastructure is often burned off or flared, as a means to deal with it when capacities in gathering systems are limited, so that oil can continue to be produced.

Routine flaring is common in the Bakken shale formation in North Dakota, the Eagle Ford shale in south-central Texas, and the Permian Basin in northwest Texas and New Mexico. In the Permian Basin alone, about US$750 million worth of gas was wasted in 2018. Also, gas flaring contributes approximately 1% of man-made atmospheric carbon dioxide emissions globally. When flares burn poorly or stop burning, methane is emitted directly to the atmosphere. In the North Dakota Bakken, >200 MMCF/day of liquids-rich raw natural gas is currently (as of April 2021) being flared, representing over 5% of all gas produced in the state.

Technologies have emerged to be able to compress gas, put the gas into high-pressure vessels that are truck-mounted, and transport that gas to market via truck rather than traditional pipelines. In order to do this, the gas must be free of all free liquids, and with the majority of the NGL removed, to avoid issues with liquids drop out as pressure is increased (the liquids can damage equipment).

In today's volatile commodity environment, producers do not have the certainty about development plans often required to make long-term infrastructure investment decisions. Producers struggle to make accurate forecasts to the midstream companies for the development and construction of appropriately sized infrastructure with long-term commitments.

New wells have high flow rates and pressures that need to be managed for the first several months days, which cause capacity issues for midstream companies. Older wells need lower back pressure to maintain production, putting them at odds with midstream companies which need pressure to maintain flow. Gas production rates, pressures, compositions, and changes in these parameters create obstacles for (a) effective transportation off-site either in pipeline or CNG trailers, and (b) on-site use for fuel or injection down-hole processes.

On-site processing and pressure management to achieve these ends has to date been (a) capital-intensive for the complete compliment of equipment required; (b) difficult and costly to move from site to site; (c) difficult to control qualities due to insufficient processing capacities; (d) not integrated for trailer loading, creating operational challenges; (e) difficult to operate, requiring highly trained technicians and physical manning of the equipment, making the cost of operation and labor high; (f) poorly controlled for residue gas and NGL qualities, creating challenges in the marketing of these products and often requiring further processing before the next stage of upgraded value; and (g) uneconomic for the producer to deploy without regulatory and/or subsidization.

A solution is desired commercial that achieves three main goals for the producer: (1) economic to deploy and operate, (2) extremely mobile, being cost effective and quick to move, and (3) capable of producing marketable residue gas. There is need for new methods and systems for processing and transporting raw natural gas from initial production locations to end markets for use or for further refinement.

SUMMARY OF THE INVENTION

The present invention addresses the aforementioned needs in the art.

Some variations provide a method for purifying and compressing natural gas, the method comprising:

(a) providing a methane-containing input stream;

(b) conveying the methane-containing input stream to a first compression sub-system configured with one or more first-compression stages;

(c) compressing the methane-containing input stream, in the first compression sub-system, to generate an initial compressed gas stream at a first pressure from about 100 psig to about 4500 psig and a first temperature from about 100° F. to about 500° F.;

(d) conveying at least a portion of the initial compressed gas stream to a low-temperature separation sub-system configured to cool the initial compressed gas stream to a second temperature from about −50° F. to about 70° F., wherein at least one liquid contaminant is removed from the low-temperature separation sub-system, thereby generating an intermediate compressed gas stream at a second pressure from about 100 psig to about 2000 psig;

(e) conveying the intermediate compressed gas stream to a second compression sub-system configured with one or more second-compression stages, to generate a compressed gas product stream at a third pressure from about 2000 psig to about 5000 psig and a third temperature that is higher than the second temperature;

(f) recovering the compressed gas product stream containing purified natural gas; and

(g) feeding the compressed gas product stream into a mobile container.

Some variations provide a method for purifying and compressing natural gas, the method comprising:

(a) providing a methane-containing input stream;

(b) conveying the methane-containing input stream to a first compression sub-system configured with one or more first-compression stages;

(c) compressing the methane-containing input stream, in the first compression sub-system, to generate an initial compressed gas stream at a first pressure from about 100 psig to about 4500 psig and a first temperature from about 100° F. to about 500° F.;

(d) conveying at least a portion of the initial compressed gas stream to a low-temperature separation sub-system configured to cool the initial compressed gas stream to a second temperature from about −50° F. to about 70° F., wherein at least one liquid contaminant is removed from the low-temperature separation sub-system, thereby generating an intermediate compressed gas stream at a second pressure from about 100 psig to about 2000 psig;

(e) conveying the intermediate compressed gas stream to a second compression sub-system configured with one or more second-compression stages, to generate a compressed gas product stream at a third pressure from about 2000 psig to about 5000 psig and a third temperature that is higher than the second temperature; and

(f) recovering the compressed gas product stream containing purified natural gas,

wherein the first compression sub-system, the low-temperature separation sub-system, and the second compression sub-system are integrated into a single unit.

In some embodiments, the methane-containing input stream is at an input pressure from about 1 psig to about 300 psig, such as from about 10 psig to about 150 psig, for example.

In some embodiments, the first compression sub-system is configured with a single first-compression stage. In other embodiments, the first compression sub-system is configured with at least two, at least three, or at least four first-compression stages.

In some embodiments, the low-temperature separation sub-system utilizes Joule-Thomson cooling of the initial compressed gas stream, wherein Joule-Thomson cooling is integrated within the low-temperature separation sub-system. In some methods, there is Joule-Thomson cooling of the initial compressed gas stream between steps (c) and (d). The Joule-Thomson cooling may cause the initial compressed gas stream to reach the second pressure, or to reach a treatment pressure that is lower than the first pressure but may be higher than the second pressure.

For example, Joule-Thomson cooling may cause the initial compressed gas stream to reach a treatment pressure that is from about 100 psig to about 1000 psig, wherein the treatment pressure is lower than the first pressure. In a certain example, Joule-Thomson cooling drops the pressure to initially about 500 psig for treatment during step (d), and then the pressure is further reduced to about 300 psig in the intermediate compressed gas stream. A Joule-Thomson expansion valve may be employed to reduce the pressure and temperature.

In some embodiments, the low-temperature separation sub-system utilizes refrigeration. In certain embodiments, the low-temperature separation sub-system utilizes both refrigeration and Joule-Thomson cooling.

In certain embodiments, refrigeration employs an intermediate heat medium. For example, a mechanical refrigeration system cools glycol, then that glycol is heat-exchanged with the compressed gas stream.

In some embodiments, the low-temperature separation sub-system utilizes one or more heat exchangers interfacing with the intermediate compressed gas stream. In these or other embodiments, the low-temperature separation sub-system utilizes one or more heat exchangers interfacing with one or more liquid streams downstream of the low-temperature separation sub-system.

The low-temperature separation sub-system may be configured as a single stage or with multiple stages. Multiple stages of the low-temperature separation sub-system may include, but are not limited to, cooling, scrubbing, dehydration, and heat exchange.

In some embodiments, at least one liquid contaminant is water. In some embodiments, at least one liquid contaminant is a C₂₊ hydrocarbon. In certain embodiments, liquid contaminants include both water and one or more C₂₊ hydrocarbons.

The low-temperature separation sub-system may be configured to dehydrate the initial compressed gas stream using a liquid solution that absorbs water out of the initial compressed gas stream to generate a water-absorbed liquid solution. In some embodiments, the liquid solution is a glycol solution, such as a solution containing ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, or a combination thereof.

In some embodiments, the method utilizes a flash unit to purge flash gas from the water-absorbed liquid solution to regenerate the liquid solution for reuse in step (d). Free water may be removed from the water-absorbed liquid solution in the flash unit. Alternatively, or additionally, free water may be removed from the water-absorbed liquid solution in another unit that is distinct from the flash unit.

In certain embodiments in which at least one liquid contaminant is a C₂₊ hydrocarbon, a C₂₊ liquid stream (generated from the low-temperature separation sub-system) is stabilized. The C₂₊ liquid stream may be stabilized by cascading the C₂₊ liquid stream countercurrently with the gas (i.e., the gas being processed) through the low-temperature separation sub-system and/or through the first compression sub-system.

In some embodiments in which at least one liquid contaminant is a C₂₊ hydrocarbon, a C₂₊ liquid stream (generated from the low-temperature separation sub-system) is stabilized. The C₂₊ liquid stream may be stabilized by processing the C₂₊ liquid stream through a stabilization or de-ethanization tower.

In some embodiments, the second compression sub-system is configured with a single second-compression stage. In other embodiments, the second compression sub-system is configured with at least two, at least three, or at least four second-compression stages. A single second-compression stage may be suitable, for instance, when the second pressure exceeds about 1500 psig.

In some embodiments, the third temperature is from about 40° F. to about 140° F., for example.

The method may further utilize an acid gas separation unit for removing carbon dioxide and/or hydrogen sulfide from the initial compressed gas stream. An acid gas separation unit, when included, may be contained within the low-temperature separation sub-system. Alternatively, the acid gas separation unit may be distinct from the low-temperature separation sub-system, but nevertheless may be integrated into a single overall unit.

In some embodiments, the method further comprises acid gas purification, in an acid gas purification unit, for removing carbon dioxide and/or hydrogen sulfide from the compressed gas product stream. The acid gas purification unit, when included, may be integrated into a single overall unit.

The methane-containing input stream may be obtained from a geological formation, such as active or abandoned oil or natural gas fields, shale plays, etc. Alternatively, or additionally, the methane-containing input stream may be obtained from anaerobic digestion of biomass or animal waste, an industrial compost facility, or a landfill.

The method is preferably conducted continuously or semi-continuously.

In some methods, the first compression sub-system and the second compression sub-system are driven by a single engine or motor. In certain methods, the first compression sub-system, the low-temperature separation sub-system, and the second compression sub-system are all driven by a single engine or motor.

The method may further include feeding the compressed gas product stream into a stationary container, such as before or after feeding the compressed gas product stream into a mobile container. Alternatively, or additionally, the method may include feeding the compressed gas product stream into a pipeline. The method may further include directly or indirectly converting the purified natural gas into one or more chemicals or fuels, or any other downstream use of the purified natural gas.

Some variations of the invention provide a system for purifying and compressing natural gas, the system comprising:

a first compression sub-system configured with one or more first-compression stages, wherein the first compression sub-system has an inlet for a methane-containing input stream and an outlet for an initial compressed gas stream;

a low-temperature separation sub-system configured in flow communication with the first compression sub-system, wherein the low-temperature separation sub-system has an inlet for the initial compressed gas stream, a gas outlet for an intermediate compressed gas stream, and at least one liquid outlet for a liquid contaminant separated from the initial compressed gas stream; and

a second compression sub-system configured with one or more second-compression stages, wherein the second compression sub-system has an inlet for the intermediate compressed gas stream and an outlet for a compressed gas product stream,

wherein the first compression sub-system, the low-temperature separation sub-system, and the second compression sub-system are integrated into a single unit.

In some embodiments, the first compression sub-system is configured with a single first-compression stage. In other embodiments, the first compression sub-system is configured with at least two, at least three, or at least four first-compression stages.

In some embodiments, the system is configured with a Joule-Thomson valve in flow communication between the first compression sub-system and the low-temperature separation sub-system. The low-temperature separation sub-system may be configured to utilize Joule-Thomson cooling of the initial compressed gas stream, wherein the Joule-Thomson cooling is integrated within the low-temperature separation sub-system.

In some embodiments, the low-temperature separation sub-system is configured to utilize refrigeration, or both refrigeration and Joule-Thomson cooling.

In certain embodiments, the low-temperature separation sub-system employs an intermediate heat medium. For example, a mechanical refrigeration sub-system cools glycol, then that glycol is heat-exchanged with the compressed gas stream.

In some systems, the low-temperature separation sub-system is configured to utilize one or more heat exchangers interfacing with the intermediate compressed gas stream. In these or other systems, the low-temperature separation sub-system may be configured to utilize one or more heat exchangers interfacing with one or more liquid streams disposed downstream of the low-temperature separation sub-system.

In some systems, at least one liquid contaminant is water, a C₂₊ hydrocarbon, or both water and one or more C₂₊ hydrocarbons.

The low-temperature separation sub-system may be configured to dehydrate the initial compressed gas stream using a liquid solution that absorbs water out of the initial compressed gas stream to generate a water-absorbed liquid solution.

In some embodiments, the system includes a flash unit configured to purge flash gas from the water-absorbed liquid solution to regenerate the liquid solution.

In certain systems, the system comprises a stabilization sub-system configured to stabilize a C₂₊ liquid stream generated from the low-temperature separation sub-system. For example, the stabilization sub-system may be configured to cascade the C₂₊ liquid stream countercurrently with the gas through the low-temperature separation sub-system and/or through the first compression sub-system. Preferably, the stabilization sub-system is part of the low-temperature separation sub-system or is part of the first compression sub-system. In other embodiments, the stabilization sub-system is disposed downstream of the low-temperature separation sub-system and receives a C₂₊ liquid stream, and stabilizes the C₂₊ liquid stream using a counterflow of gas that is not necessarily the compressed gas stream from the low-temperature separation sub-system.

Alternatively, or additionally, the system may include a stabilization or de-ethanization tower to stabilize a C₂₊ liquid stream generated from the low-temperature separation sub-system. The C₂₊ liquid stream may be stabilized by processing the C₂₊ liquid stream through a stabilization or de-ethanization tower.

The second compression sub-system may be configured with a single second-compression stage. Alternatively, and more typically (but not necessarily), the second compression sub-system is configured with at least two, at least three, or at least four second-compression stages.

In some embodiments, the system further includes an acid gas separation unit configured for removing carbon dioxide and/or hydrogen sulfide from the initial compressed gas stream. The acid gas separation unit, when included, may be contained within the low-temperature separation sub-system. Alternatively, the acid gas separation unit may be physically distinct from the low-temperature separation sub-system, but still may be integrated into the single overall unit.

In some embodiments, the system further comprises an acid gas purification unit configured for removing carbon dioxide and/or hydrogen sulfide from the compressed gas product stream. The acid gas purification unit, when included, may be integrated into the single overall unit.

In some systems, the first compression sub-system and the second compression sub-system are configured to be driven by a single engine or motor. In certain systems, the first compression sub-system, the low-temperature separation sub-system, and the second compression sub-system are all configured to be driven by a single engine or motor.

The outlet for the compressed gas product stream is preferably configured to connect to a mobile container. In some embodiments of the virtual gas pipeline system, the system further comprises the mobile container (or multiple mobile containers).

BRIEF DESCRIPTION OF THE FIGURE

FIG. 1 is an exemplary block-flow diagram, according to some embodiments of the invention.

DETAILED DESCRIPTION OF EMBODIMENTS OF THE INVENTION

This description will enable one skilled in the art to make and use the invention, and it describes several embodiments, adaptations, variations, alternatives, and uses of the invention. These and other embodiments, features, and advantages of the present invention will become more apparent to those skilled in the art when taken with reference to the following detailed description of the invention in conjunction with the accompanying drawings.

As used in this specification and the appended claims, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly indicates otherwise. Unless defined otherwise, all technical and scientific terms used herein have the same meaning as is commonly understood by one of ordinary skill in the art to which this invention belongs.

Unless otherwise indicated, all numbers expressing reaction conditions, stoichiometries, concentrations of components, and so forth used in the specification and claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending at least upon a specific analytical technique.

The term “comprising,” which is synonymous with “including,” “containing,” or “characterized by” is inclusive or open-ended and does not exclude additional, unrecited elements or method steps. “Comprising” is a term of art used in claim language which means that the named claim elements are essential, but other claim elements may be added and still form a construct within the scope of the claim.

As used herein, the phrase “consisting of” excludes any element, step, or ingredient not specified in the claim. When the phrase “consists of” (or variations thereof) appears in a clause of the body of a claim, rather than immediately following the preamble, it limits only the element set forth in that clause; other elements are not excluded from the claim as a whole. As used herein, the phrase “consisting essentially of” limits the scope of a claim to the specified elements or method steps, plus those that do not materially affect the basis and novel characteristic(s) of the claimed subject matter.

With respect to the terms “comprising,” “consisting of,” and “consisting essentially of,” where one of these three terms is used herein, the presently disclosed and claimed subject matter may include the use of either of the other two terms. Thus in some embodiments not otherwise explicitly recited, any instance of “comprising” may be replaced by “consisting of” or, alternatively, by “consisting essentially of.”

The present invention, in some variations, is predicated on integrated methods and single-unit systems for purifying and compressing natural gas. Heretofore, natural gas processing has been done upstream, prior to compression, due to difficulties associated with high-pressure processing. The inventors have designed new approaches to overcome these difficulties and provide more-efficient purification and compression of natural gas. The invention is applicable to the natural gas industry, primarily as an alternate method of processing and transporting raw natural gas from initial production locations to end markets for use or for further refinement.

Raw natural gas is unprocessed natural gas in which liquid dropout due to heavier hydrocarbons (C₂₊) during compression, transportation, and decompression is a concern, and/or hydrating due to high water content is a concern. The present invention provides methods and systems to handle both water and heavier hydrocarbons inter-stage in the gas compression process itself. When the invention is utilized, raw natural gas is purified and compressed, providing a compressed gas product. The compressed gas product may be used in a virtual pipeline service, for example, in on-site processing of natural gas for fuel or down-hole applications. The compressed gas product would otherwise be flared or unsuitable for use.

The present invention, in various embodiments, may utilize a number of aspects. One aspect employs a Joule-Thomson (“J-T”) valve, dropping from a high interstage pressure to a lower treatment pressure for liquids separation, then continuing to compress. Another aspect employs interstage cooling with refrigeration and process heat exchange in addition to, or instead of, J-T pressure reduction. Another aspect employs glycol injection interstage for water separation. Yet another aspect utilizes an inlet separator as a flash tank in a glycol dehydration process to handle flash gas of the glycol regeneration process. Still another aspect pushes free water from an inlet separator to a glycol regenerator for disposal.

There are a number of benefits associated with the present invention, in various embodiments. Combining CNG and natural gas processing reduces the complexity of the facility. The invention enables scaling down of equipment required for flare gas capture operations. The invention improves capital cost efficiency to allow processing of small volumes at economic rates. The invention achieves fuel-quality residue gas to allow for transportation directly to market, or use on site as a fuel or down-hole use, for example. Finally, because the entire system is integrated into a single unit, movement and set-up is convenient and cost-effective.

Some variations provide a method for purifying and compressing natural gas, the method comprising:

(a) providing a methane-containing input stream;

(b) conveying the methane-containing input stream to a first compression sub-system configured with one or more first-compression stages;

(c) compressing the methane-containing input stream, in the first compression sub-system, to generate an initial compressed gas stream at a first pressure from about 100 psig to about 4500 psig and a first temperature from about 100° F. to about 500° F.;

(d) conveying at least a portion of the initial compressed gas stream to a low-temperature separation sub-system configured to cool the initial compressed gas stream to a second temperature from about −50° F. to about 70° F., wherein at least one liquid contaminant is removed from the low-temperature separation sub-system, thereby generating an intermediate compressed gas stream at a second pressure from about 100 psig to about 2000 psig;

(e) conveying the intermediate compressed gas stream to a second compression sub-system configured with one or more second-compression stages, to generate a compressed gas product stream at a third pressure from about 2000 psig to about 5000 psig and a third temperature that is higher than the second temperature; and

(f) recovering the compressed gas product stream containing purified natural gas,

wherein the first compression sub-system, the low-temperature separation sub-system, and the second compression sub-system are integrated into a single unit.

In some embodiments, the methane-containing input stream is at an input pressure from about 1 psig to about 300 psig. In various embodiments, the containing input stream is at an input pressure of about, at least about, or at most about 1, 5, 10, 15, 20, 25, 30, 40, 50, 60, 70, 80, 90, 100, 110, 120, 130, 140, 150, 160, 170, 180, 190, 200, 210, 220, 230, 240, 250, 260, 270, 280, 290, or 300 psig, or higher.

In some embodiments, the first compression sub-system is configured with a single first-compression stage. In other embodiments, the first compression sub-system is configured with at least two, at least three, or at least four first-compression stages.

In some embodiments, the low-temperature separation sub-system utilizes Joule-Thomson cooling of the initial compressed gas stream, wherein Joule-Thomson cooling is integrated within the low-temperature separation sub-system. In some methods, there is Joule-Thomson cooling of the initial compressed gas stream between steps (c) and (d). The Joule-Thomson cooling may cause the initial compressed gas stream to reach the second pressure, or to reach a treatment pressure that is lower than the first pressure but may be higher than the second pressure.

For example, Joule-Thomson cooling may cause the initial compressed gas stream to reach a treatment pressure that is from about 100 psig to about 1000 psig, wherein the treatment pressure is lower than the first pressure. In a certain example, Joule-Thomson cooling drops the pressure to initially about 500 psig for treatment during step (d), and then the pressure is further reduced to about 300 psig in the intermediate compressed gas stream. A Joule-Thomson expansion valve may be employed to reduce the pressure and temperature.

In some embodiments, the low-temperature separation sub-system utilizes refrigeration. In certain embodiments, the low-temperature separation sub-system utilizes both refrigeration and Joule-Thomson cooling.

In certain embodiments, refrigeration employs an intermediate heat medium. For example, a mechanical refrigeration system cools glycol, then that glycol is heat-exchanged with the compressed gas stream.

In some embodiments, the low-temperature separation sub-system utilizes one or more heat exchangers interfacing with the intermediate compressed gas stream. In these or other embodiments, the low-temperature separation sub-system utilizes one or more heat exchangers interfacing with one or more liquid streams downstream of the low-temperature separation sub-system.

The low-temperature separation sub-system may be configured as a single stage or with multiple stages. Multiple stages of the low-temperature separation sub-system may include, but are not limited to, cooling, scrubbing, dehydration, and heat exchange.

In some embodiments, at least one liquid contaminant is water. In some embodiments, at least one liquid contaminant is a C₂₊ hydrocarbon. In certain embodiments, liquid contaminants include both water and one or more C₂₊ hydrocarbons. C₂₊ hydrocarbons may include, but are not limited to, ethane, propane, butanes, and natural gasoline (condensate).

In step (d), the liquid contaminant is not necessarily completely removed. For example, when the liquid contaminant is water, the water may be at least about 50%, 60%, 70%, 80%, 90%, 95%, 99%, or 100% removed during step (d). When the liquid contaminant is a C₂₊ hydrocarbon, the C₂₊ hydrocarbon may be at least about 50%, 60%, 70%, 80%, 90%, 95%, 99%, or 100% removed during step (d). The removal efficiency of water and C₂₊ hydrocarbon(s) may be different, although preferably is very high (>90%) for both of these contaminants.

The low-temperature separation sub-system may be configured to dehydrate the initial compressed gas stream using a liquid solution that absorbs water out of the initial compressed gas stream to generate a water-absorbed liquid solution. In some embodiments, the liquid solution is a glycol solution, such as a solution containing ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, or a combination thereof.

In certain embodiments, there is injection of a glycol solution into an individual stage, or between stages, of the low-temperature separation sub-system.

In certain embodiments, there is scrubbing in an individual stage of the low-temperature separation sub-system, in an inter-stage scrubber.

In some embodiments, the method utilizes a flash unit to purge flash gas from the water-absorbed liquid solution to regenerate the liquid solution for reuse in step (d). Free water may be removed from the water-absorbed liquid solution in the flash unit. Alternatively, or additionally, free water may be removed from the water-absorbed liquid solution in another unit that is distinct from the flash unit. In certain embodiments, a compressor inlet scrubber is configured as a flash tank for integrated dehydration.

In some embodiments in which at least one liquid contaminant is a C₂₊ hydrocarbon, a C₂₊ liquid stream (generated from the low-temperature separation sub-system) is stabilized. The C₂₊ liquid stream may be stabilized by cascading the C₂₊ liquid stream countercurrently with the gas (i.e., the gas being processed) through the low-temperature separation sub-system and/or through the first compression sub-system. Alternatively, or additionally, the C₂₊ liquid stream may be stabilized by processing the C₂₊ liquid stream through a stabilization or de-ethanization tower.

In some embodiments, the second compression sub-system is configured with a single second-compression stage. In other embodiments, the second compression sub-system is configured with at least two, at least three, or at least four second-compression stages. A single second-compression stage may be suitable, for instance, when the second pressure exceeds about 1500 psig.

In some embodiments, the third temperature is from about 40° F. to about 140° F., for example. In various embodiments, the third temperature is about, at least about, or at most about 40° F., 50° F., 60° F., 70° F., 80° F., 90° F., 100° F., 110° F., 120° F., 130° F., or 140° F., including any intervening ranges.

The method may further utilize an acid gas separation unit for removing carbon dioxide and/or hydrogen sulfide from the initial compressed gas stream. An acid gas separation unit, when included, may be contained within the low-temperature separation sub-system. Alternatively, the acid gas separation unit may be distinct from the low-temperature separation sub-system, but nevertheless may be integrated into the single overall unit.

In some embodiments, the method further comprises acid gas purification, in an acid gas purification unit, for removing carbon dioxide and/or hydrogen sulfide from the compressed gas product stream. The acid gas purification unit, when included, may be integrated into the single overall unit.

Amine-based systems are known for removing CO₂ and H₂S from gas streams. In such systems, the amine functions as a solvent to dissolve CO₂, which is later removed by adjusting conditions such as temperature. An amine-based system may be utilized to remove CO₂ and/or H₂S from the initial compressed gas stream and/or from the compressed gas product stream.

The methane-containing input stream may be obtained from a geological formation, such as active or abandoned oil or natural gas fields, shale plays, etc. Alternatively, or additionally, the methane-containing input stream may be obtained from anaerobic digestion of biomass or animal waste, an industrial compost facility, or a landfill.

The method is preferably conducted continuously or semi-continuously. There may be various recycle schemes in the method, including during steady-state operation, start-up or shut-down. For example, there may be cold recycling of a high-pressure stream to the low-temperature separation sub-system as a means for turn down and/or start-up while preferably remaining on spec for the compressed gas product.

In some methods, the first compression sub-system and the second compression sub-system are driven by a single engine or motor. The low-temperature separation sub-system may be driven by a different engine or motor. In certain methods, the first compression sub-system, the low-temperature separation sub-system, and the second compression sub-system are all driven by a single engine or motor.

The method may further include feeding the compressed gas product stream into a stationary container or a mobile container. Alternatively, or additionally, the method may include feeding the compressed gas product stream into a pipeline. The method may further include directly or indirectly converting the purified natural gas into one or more chemicals or fuels, or any other downstream use of the purified natural gas.

Some variations of the invention provide a virtual gas pipeline system for purifying and compressing natural gas, the system comprising:

a first compression sub-system configured with one or more first-compression stages, wherein the first compression sub-system has an inlet for a methane-containing input stream and an outlet for an initial compressed gas stream;

a low-temperature separation sub-system configured in flow communication with the first compression sub-system, wherein the low-temperature separation sub-system has an inlet for the initial compressed gas stream, a gas outlet for an intermediate compressed gas stream, and a liquid outlet (or multiple liquid outlets) for a liquid contaminant separated from the initial compressed gas stream; and

a second compression sub-system configured with one or more second-compression stages, wherein the second compression sub-system has an inlet for the intermediate compressed gas stream and an outlet for a compressed gas product stream,

wherein the first compression sub-system, the low-temperature separation sub-system, and the second compression sub-system are integrated into a single unit.

A “virtual gas pipeline system” refers to a system that is able to utilize a mobile container for the compressed gas product stream. The mobile container is suitable for ultimately injecting the compressed gas product stream into an actual natural gas pipeline, or as an alternative means for transporting compressed natural gas, rather than a physical pipeline, or a combination thereof.

In some embodiments, the first compression sub-system is configured with a single first-compression stage. In other embodiments, the first compression sub-system is configured with at least two, at least three, or at least four first-compression stages.

In some embodiments, the system is configured with a Joule-Thomson valve in flow communication between the first compression sub-system and the low-temperature separation sub-system. The low-temperature separation sub-system may be configured to utilize Joule-Thomson cooling of the initial compressed gas stream, wherein the Joule-Thomson cooling is integrated within the low-temperature separation sub-system.

In some embodiments, the low-temperature separation sub-system is configured to utilize refrigeration, or both refrigeration and Joule-Thomson cooling.

In certain embodiments, the low-temperature separation sub-system employs an intermediate heat medium. For example, a mechanical refrigeration sub-system cools glycol, then that glycol is heat-exchanged with the compressed gas stream.

In some systems, the low-temperature separation sub-system is configured to utilize one or more heat exchangers interfacing with the intermediate compressed gas stream. In these or other systems, the low-temperature separation sub-system may be configured to utilize one or more heat exchangers interfacing with one or more liquid streams disposed downstream of the low-temperature separation sub-system.

In some systems, at least one liquid contaminant is water, a C₂₊ hydrocarbon, or both water and one or more C₂₊ hydrocarbons.

The low-temperature separation sub-system may be configured to dehydrate the initial compressed gas stream using a liquid solution that absorbs water out of the initial compressed gas stream to generate a water-absorbed liquid solution.

In some embodiments, the system includes a flash unit configured to purge flash gas from the water-absorbed liquid solution to regenerate the liquid solution.

In certain systems, the system comprises a stabilization sub-system configured to stabilize a C₂₊ liquid stream generated from the low-temperature separation sub-system. For example, the stabilization sub-system may be configured to cascade the C₂₊ liquid stream countercurrently with the gas through the low-temperature separation sub-system and/or through the first compression sub-system. Preferably, the stabilization sub-system is part of the low-temperature separation sub-system and/or is part of the first compression sub-system. In other embodiments, the stabilization sub-system is disposed downstream of the low-temperature separation sub-system and receives a C₂₊ liquid stream, and stabilizes the C₂₊ liquid stream using a counterflow of gas that is not necessarily the compressed gas stream from the low-temperature separation sub-system.

Alternatively, or additionally, the system may include a stabilization or de-ethanization tower to stabilize a C₂₊ liquid stream generated from the low-temperature separation sub-system. The C₂₊ liquid stream may be stabilized by processing the C₂₊ liquid stream through a stabilization or de-ethanization tower.

The second compression sub-system may be configured with a single second-compression stage. Alternatively, and more typically (but not necessarily), the second compression sub-system is configured with at least two, at least three, or at least four second-compression stages.

In some embodiments, the system further includes an acid gas separation unit configured for removing carbon dioxide and/or hydrogen sulfide from the initial compressed gas stream. The acid gas separation unit, when included, may be contained within the low-temperature separation sub-system. Alternatively, the acid gas separation unit may be physically distinct from the low-temperature separation sub-system, but still may be integrated into the single overall unit.

In some embodiments, the system further comprises an acid gas purification unit configured for removing carbon dioxide and/or hydrogen sulfide from the compressed gas product stream. The acid gas purification unit, when included, may be integrated into the single overall unit.

In some systems, the first compression sub-system and the second compression sub-system are configured to be driven by a single engine or motor. In certain systems, the first compression sub-system, the low-temperature separation sub-system, and the second compression sub-system are all configured to be driven by a single engine or motor. Optionally, the low-temperature separation sub-system is driven by a different engine or motor.

In this specification, a “single unit” means a unit that is designed and built as one unit, or a plurality of sub-units that are configured to be connected together (integrated), to form a single unit. It will be recognized that for a certain period of time, a sub-unit could be disconnected, such as during transport or maintenance. As one example of a single unit including multiple sub-units, a single unit may consist of two trailers have multiple interconnections.

The outlet for the compressed gas product stream is preferably configured to connect to a mobile container. That is, the outlet is preferably configured with suitable valves, hoses, and/or other flow devices that enable to reliable gas connection to the mobile container. In some embodiments of the virtual gas pipeline system, the system further comprises the mobile container (or multiple mobile containers).

FIG. 1 is an exemplary block-flow diagram, according to some embodiments of the invention. The system of FIG. 1 comprises a first compression sub-system, a low-temperature separation sub-system, and a second compression sub-system that are all integrated into a single unit. Typical gas pressure ranges are indicated in the drawing. The primary product is purified natural gas, and co-products may include water and/or C₂₊ hydrocarbon liquids.

Various embodiments of the invention will now be further described, without limiting the scope of the invention.

Raw natural gas enters the system for purifying and compressing natural gas (which may also be referred to as a “compression/processing unit” or similar designation). The inlet to the system may be via a third-party pipe connection, which typically provides the raw natural gas at low pressure. The low-pressure raw gas enters the system and undergoes multiple stages of compression and purification, which may include glycol injection, J-T cooling, refrigeration, separation, reaction, heat exchange, or combinations thereof After purification, the treated natural gas stream then undergoes one or more additional stages of compression to reach a CNG pressure and is then directed off-skid, such as for CNG transportation away from the site, or for on-site consumption or further pipeline transportation. Water, if any, that is separated from the natural gas may be stored in a water storage tank for truck off-loading and disposal. Alternatively, or additionally, water may be boiled off to the atmosphere. Natural gas liquid (NGLs) separated from the natural gas may be directed to a NGL tank for storage and off-loading for transportation to market.

The system of the invention will typically be located at an industrial facility that includes the system as well as NGL storage tank(s) attached mechanically via pipe or hose and with electrical cables for power, control, and communication. The system may be fabricated at a first site and then installed at the industrial facility, or the system may be fabricated directly at the desired industrial facility.

The system for purifying and compressing natural gas may include a natural gas engine powering the compressor, wherein the engine may be from about 0.1 hp to about 1000 hp, depending on overall capacity. The engine preferably combusts natural gas for power, although that is not strictly necessary. The compressor is preferably (but not necessarily) a reciprocating compressor. All equipment may be placed on a trailer or structural skid for transportation. There may be compressed natural gas (CNG) tube trailer connections for compressing gas directly into tube trailers.

As disclosed above in detail, there is inter-stage processing to remove water and/or heavy hydrocarbons. In some embodiments, the compressor in configured for multiple stages of compression from flare header pressures (typically <100 psig) to CNG pressure (e.g., 4500 psig). This will allow conservation of the raw natural gas and transformation to saleable products—residue methane of pipeline quality and NGLs ready for sale—through on-site processing, so that products can be delivered to markets via road transportation or used on-site as fuels.

The raw natural gas pressure may vary, such as from about 1 psig to about 300 psig (other pressures are possible). In general, the raw natural gas contains undesirable liquid contaminants (and possibly vapor contaminants) to be removed. The composition of raw natural gas is typically about 60-90 vol % methane, 2-10 vol % ethane, 1-5 vol % propane, 0.5-2 vol % butanes, 0.1-1 vol % pentanes, 0-0.2 vol % oxygen, 0-1 vol % nitrogen, and 0-1 vol % (or more) water, depending on the source (e.g., oil well versus anaerobic digestor).

In some embodiments, the raw natural gas is dirty gas containing methane. In some embodiments, the raw natural gas is wet gas containing methane (“wet” refers to water). In some embodiments, the raw natural gas is dirty and wet gas containing methane. The raw natural gas may have a high liquids content compared to normal CNG-quality natural gas, and otherwise not be of sufficient quality to enter a sales pipeline or engine for consumption. The raw natural gas may have water entrained in the gas and in many cases will be water-saturated.

In some embodiments, upstream of the first compression sub-system, inlet safety equipment is employed. Inlet safety equipment may include, but is not limited to, emergency shutdown valves, inlet liquids slug catchers, inlet pressure control devices, etc.

A first compression sub-system, containing 1 to 4 individual compression stages, for example, increases the gas pressure typically to 500-1000 psig or as high as 4500 psig. The gas temperature at the inlet to the first compression sub-system may be from about 0° F. to about 200° F., such as about 150° F., for example. The gas temperature varies through the compression stages, primarily dictated by thermodynamics at the relevant pressures, as well as heat exchange in the system. The first compression sub-system preferably employs a reciprocating natural gas compressor.

The gas exits the first compression sub-system and flows to a low-temperature separation sub-system. Preferably, there is Joule-Thomson (J-T) cooling and pressure reduction between the first compression sub-system and the low-temperature separation sub-system, or within the low-temperature separation sub-system. With J-T cooling/expansion, the gas pressure may be reduced to about 100-1000 psig (e.g., 500 psig), for example. A J-T valve drops the natural gas pressure to an optimal liquids separation pressure and provides further temperature reduction. In other embodiments, there is refrigeration but no J-T cooling.

In the low-temperature separation sub-system, there may be gas-gas heat exchange, gas-liquid heat exchange, or both types of heat exchange. For example, there may be a gas-gas heat exchanger for cooling gas using a gas exit stream from the low-temperature separation sub-system. Alternatively, or additionally, there may be a gas-liquid heat exchanger for cooling gas with a liquid exit stream from the low-temperature separation sub-system.

The temperature of the low-temperature separation sub-system may range from about −50° F. to +32° F., such as from about −20° F. to −30° F., for example. Unless otherwise noted, the temperature of the low-temperature separation sub-system refers to the gas temperature as it is being processed, noting that the temperature of other components such as glycol solutions, as well as the temperature of the equipment itself, may be different. In various embodiments, the temperature of the low-temperature separation sub-system is about −50° F., −40° F., −30° F., −20° F., −10° F., 0° F., 10° F., 20° F., 30° F., 40° F., or 50° F., including all intervening ranges. Also note that the low-temperature separation sub-system may employ multiple temperatures; when there are multiple separation or cooling stages within the low-temperature separation sub-system, each distinct stage will typically be operated at a distinct temperature.

Glycols may be added to the low-temperature separation sub-system to dehydrate the gas. The glycols may be selected from triethylene glycol (TEG), diethylene glycol (DEG), ethylene glycol (MEG), and/or tetraethylene glycol (TREG). Glycol injection can prevent freezing and dehydrate the natural gas. There may be integration of glycol regeneration with gas scrubbers.

There is preferably a liquid exit stream from the low-temperature separation sub-system from which water, C₂₊ liquids, spent glycols, and/or other components are withdrawn. This liquid exit stream may be a slurry. The liquid exit stream may be further fractionated to recover specific components. For example, the exit stream may be sent to a flash unit or distillation column, and glycol may be recovered and reused.

There is also a gas exit stream from the low-temperature separation sub-system. The gas exit stream is conveyed to a second compression sub-system that itself is configured with one or more compression stages. Prior to the second compression sub-system, or within the second compression sub-system, the gas may be warmed back up, to a gas temperature such as about 30° F. to about 200° F., preferably about 40° F. to about 140° F. The pressure at the exit of the second compression sub-system may be up to 5000 psig, such as the pressure required for the final use, container (e.g., truck) requirements, or pipeline specifications.

The low-temperature separation sub-system thus separates the gas stream into at least two distinct streams: a clean residue gas and a NGL with water/glycol liquid mixture. In certain embodiments, the liquid mixture cascades down through liquid separators to allow gas to flash off and stabilize the liquids, such as in a stabilization sub-system that cascades transmission backwards through the interstage compression separators. The stabilized NGLs may then have the glycol/water separated out for regeneration and reinjection. The stabilized NGLs may be transported to a storage tank and ultimately off-loaded for transportation to market. The residue gas from the low-temperature separation sub-system may then be conveyed to a gas-gas heat exchanger to warm back up, prior to introduction to the second compression sub-system. The water that is separated from the glycol in a reboiler or other separation unit may be stored in a water storage tank for truck off-loading and disposal. Alternatively, or additionally, water may be boiled off to the atmosphere. The glycol that is regenerated is preferably reinjected back into the natural gas, in a closed-loop system.

A second compression sub-system, containing 1 to 4 individual compression stages, for example, increases the gas pressure typically to 2000-4500 psig or higher (e.g., a CNG transportation pressure). The second compression sub-system preferably employs one or more reciprocating natural gas compressors, which may be driven by the same engine that drives reciprocating natural gas compressor(s) in the first compression sub-system. The treated and compressed natural gas, i.e. the CNG product, may be directed to a CNG tube trailer (off-skid) for transportation away from the site or for on-site use.

The specific pressure of the CNG product (purified natural gas) may vary, such as about, at least about, or at most about 2500, 2600, 2700, 2800, 2900, 3000, 3100, 3200, 3300, 3400, 3500, 3600, 3700, 3800, 3900, 4000, 4100, 4200, 4300, 4400, or 4500 psig, including any intervening ranges. In certain embodiments, a relatively low-pressure CNG is generated, at a pressure such as 1440 psig (lower than conventional CNG), purified according to the disclosure herein.

As will be appreciated by a skilled engineer, the methods and systems of the invention may employ various process sensors and control schemes to monitor and control gas pressures, temperatures, flow rates, and compositions throughout processing. Standard or customized gas pressure, temperature, and flow gauges may be employed. Gas composition may be monitored by withdrawing a gas sample and subjecting the gas sample to mass spectrometry, gas chromatography, or FTIR spectroscopy, for example. Gas composition may be measured, for example, according to ASTM D7833, D1945, D1946, or D3588, which test methods are incorporated by reference herein. Process adjustments may be made dynamically using measurements of gas pressures, temperatures, flow rates, and/or compositions, if deemed necessary or desirable, using well-known principles of process control (feedback, feedforward, proportional-integral-derivative logic, etc.).

As will also be appreciated by a skilled artisan, the methods and systems of the invention may utilize various process simulations, modeling, and engineering calculations, both in the initial design as well as during operation. Process calculations and simulations may be performed using process simulation software as well as gas compressor simulation software. These simulations may be performed for a range of gas compositions and run parameters to ensure robustness of the methods and systems.

The present invention may be applied to a wide range of throughputs and product generation capacities, such as from about 10 thousand to about 10 million standard cubic feet per day (SCFD) of purified natural gas. A typical order of magnitude is 1 million standard cubic feet per day, 1 MMSCFD, of purified natural gas that is produced.

In addition to the purified natural gas which is the primary product, there may be a number of co-products from the methods and systems of the invention. Co-products may include, but are not limited to, C₂₊ hydrocarbons, CO₂, and H₂O. There may be excess electricity generated on-site, and that electricity may be sold as a co-product.

There is a wide variety of uses of the purified natural gas; the invention is not limited to any particular downstream use. As described above, the purified natural gas may first be filled into a container, such as a mobile container (e.g., on a truck or train car), or may be injected into a pipeline for transportation to a location of use. Exemplary uses will be described.

The purified natural gas will typically be utilized for its methane content. Methane is an excellent fuel and may be combusted to generate energy for heating, for electricity generation, or for power (such as in natural gas vehicles). Natural gas is a major source of electricity generation through the use of cogeneration, gas turbines, and steam turbines. Most grid-peaking power plants and some off-grid engine generators utilize natural gas. Particularly high efficiencies can be achieved through combining gas turbines with a steam turbine in combined-cycle mode. Natural gas burns more cleanly than other fuels, such as oil and coal.

Methane may also be used as a chemical feedstock. For example, methane may be used to produce hydrogen gas using steam methane reforming or partial oxidation. In methane reforming or partial oxidation, methane is converted to syngas (H₂ and CO) and the hydrogen may be extracted from the syngas. That hydrogen may then be used as a fuel or to generate a chemical, such as ammonia (Haber process). Other uses of hydrogen include oil refining (e.g., hydrotreating) and hydrogen fuel cells, to name a few.

Methane-derived syngas may be a feedstock for another chemical process. Syngas may be chemically converted into alcohols (such as methanol), olefins (such as ethylene), oxygenates (such as dimethyl ether), paraffins, linear or branched C₅-C₁₅ hydrocarbons, diesel fuel, gasoline, or waxes, such as by Fischer-Tropsch chemistry. Syngas can be converted into isobutane by isosynthesis. Syngas can be converted to aldehydes and alcohols by oxosynthesis. Syngas can be converted to methanol as an intermediate for making methanol derivatives including dimethyl ether, acetic acid, ethylene, propylene, or formaldehyde. Syngas can also be converted to energy using energy-conversion devices such as solid-oxide fuel cells, Stirling engines, micro-turbines, internal combustion engines, thermo-electric generators, scroll expanders, gas burners, or thermo-photovoltaic devices.

In this detailed description, reference has been made to multiple embodiments of the invention and non-limiting examples relating to how the invention can be understood and practiced. Other embodiments that do not provide all of the features and advantages set forth herein may be utilized, without departing from the spirit and scope of the present invention. This invention incorporates routine experimentation and optimization of the methods and systems described herein. Such modifications and variations are considered to be within the scope of the invention defined by the claims.

All publications, patents, and patent applications cited in this specification are herein incorporated by reference in their entirety as if each publication, patent, or patent application were specifically and individually put forth herein.

Where methods and steps described above indicate certain events occurring in certain order, those of ordinary skill in the art will recognize that the ordering of certain steps may be modified and that such modifications are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially. Therefore, to the extent there are variations of the invention, which are within the spirit of the disclosure or equivalent to the inventions found in the appended claims, it is the intent that this patent will cover those variations as well. The present invention shall only be limited by what is claimed. 

What is claimed is:
 1. A method for purifying and compressing natural gas, said method comprising: (a) providing a methane-containing input stream; (b) conveying said methane-containing input stream to a first compression sub-system configured with one or more first-compression stages; (c) compressing said methane-containing input stream, in said first compression sub-system, to generate an initial compressed gas stream at a first pressure from about 100 psig to about 4500 psig and a first temperature from about 100° F. to about 500° F.; (d) conveying at least a portion of said initial compressed gas stream to a low-temperature separation sub-system configured to cool said initial compressed gas stream to a second temperature from about −50° F. to about 70° F., wherein at least one liquid contaminant is removed from said low-temperature separation sub-system, thereby generating an intermediate compressed gas stream at a second pressure from about 100 psig to about 2000 psig; (e) conveying said intermediate compressed gas stream to a second compression sub-system configured with one or more second-compression stages, to generate a compressed gas product stream at a third pressure from about 2000 psig to about 5000 psig and a third temperature that is higher than said second temperature; (f) recovering said compressed gas product stream containing purified natural gas; and (g) feeding said compressed gas product stream into a mobile container.
 2. The method of claim 1, wherein said methane-containing input stream is at an input pressure from about 1 psig to about 300 psig.
 3. The method of claim 1, wherein said first compression sub-system is configured with a single first-compression stage.
 4. The method of claim 1, wherein said first compression sub-system is configured with at least two first-compression stages.
 5. The method of claim 1, wherein said first compression sub-system is configured with at least three first-compression stages.
 6. The method of claim 1, wherein said first compression sub-system is configured with four or more first-compression stages.
 7. The method of claim 1, wherein said low-temperature separation sub-system utilizes Joule-Thomson cooling of said initial compressed gas stream, and wherein said Joule-Thomson cooling is integrated within said low-temperature separation sub-system.
 8. The method of claim 7, wherein said Joule-Thomson cooling causes said initial compressed gas stream to reach said second pressure.
 9. The method of claim 1, wherein said method utilizes Joule-Thomson cooling of said initial compressed gas stream between steps (c) and (d).
 10. The method of claim 9, wherein said Joule-Thomson cooling causes said initial compressed gas stream to reach a treatment pressure that is from about 100 psig to about 1000 psig, and wherein said treatment pressure is lower than said first pressure.
 11. The method of claim 1, wherein said low-temperature separation sub-system utilizes refrigeration.
 12. The method of claim 1, wherein said low-temperature separation sub-system utilizes both refrigeration and Joule-Thomson cooling.
 13. The method of claim 1, wherein said low-temperature separation sub-system utilizes one or more heat exchangers interfacing with said intermediate compressed gas stream.
 14. The method of claim 1, wherein said low-temperature separation sub-system utilizes one or more heat exchangers interfacing with one or more liquid streams downstream of said low-temperature separation sub-system.
 15. The method of claim 1, wherein said at least one liquid contaminant is water or a C₂₊ hydrocarbon.
 16. The method of claim 1, wherein low-temperature separation sub-system is configured to dehydrate said initial compressed gas stream using a liquid solution that absorbs water out of said initial compressed gas stream to generate a water-absorbed liquid solution.
 17. The method of claim 16, wherein said liquid solution is a glycol solution.
 18. The method of claim 17, wherein said glycol solution contains ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, or a combination thereof.
 19. The method of claim 16, wherein said method utilizes a flash unit to purge flash gas from said water-absorbed liquid solution to regenerate said liquid solution for reuse in step (d).
 20. The method of claim 19, wherein free water is removed from said water-absorbed liquid solution in said flash unit.
 21. The method of claim 19, wherein free water is removed from said water-absorbed liquid solution in another unit that is distinct from said flash unit.
 22. The method of claim 1, wherein said at least one liquid contaminant is a C₂₊ hydrocarbon, wherein a C₂₊ liquid stream is generated from said low-temperature separation sub-system, and wherein said C₂₊ liquid stream is stabilized.
 23. The method of claim 22, wherein said C₂₊ liquid stream is stabilized by cascading said C₂₊ liquid stream countercurrently with gas through said low-temperature separation sub-system and/or through said first compression sub-system.
 24. The method of claim 22, wherein said C₂₊ liquid stream is stabilized by processing said C₂₊ liquid stream through a stabilization or de-ethanization tower.
 25. The method of claim 1, wherein said second compression sub-system is configured with a single second-compression stage.
 26. The method of claim 1, wherein said second compression sub-system is configured with at least two second-compression stages.
 27. The method of claim 1, wherein said third temperature is from about 40° F. to about 140° F.
 28. The method of claim 1, wherein said method utilizes an acid gas separation unit for removing carbon dioxide and/or hydrogen sulfide from said initial compressed gas stream.
 29. The method of claim 28, wherein said acid gas separation unit is contained within said low-temperature separation sub-system.
 30. The method of claim 28, wherein said acid gas separation unit is distinct from said low-temperature separation sub-system, wherein said first compression sub-system, said low-temperature separation sub-system, and said second compression sub-system are integrated into a single unit, and wherein said acid gas separation unit is integrated into said single unit.
 31. The method of claim 1, wherein said method further utilizes an acid gas purification unit for removing carbon dioxide and/or hydrogen sulfide from said compressed gas product stream.
 32. The method of claim 31, wherein said first compression sub-system, said low-temperature separation sub-system, and said second compression sub-system are integrated into a single unit, and wherein said acid gas purification unit is integrated into said single unit.
 33. The method of claim 1, wherein said methane-containing input stream is obtained from a geological formation.
 34. The method of claim 1, wherein said methane-containing input stream is obtained from anaerobic digestion of biomass or animal waste, an industrial compost facility, or a landfill.
 35. The method of claim 1, wherein method is conducted continuously or semi-continuously.
 36. The method of claim 1, wherein said first compression sub-system and said second compression sub-system are driven by a single engine or motor.
 37. The method of claim 1, wherein said first compression sub-system, said low-temperature separation sub-system, and said second compression sub-system are integrated into a single unit.
 38. The method of claim 1, wherein said method further comprises feeding said compressed gas product stream into a stationary container.
 39. The method of claim 1, wherein said method further comprises feeding said compressed gas product stream into a pipeline.
 40. The method of claim 1, wherein said method further comprises directly or indirectly converting said purified natural gas into one or more chemicals or fuels. 